Crude petroleum oil and gaseous hydrocarbons are produced by extraction from subterranean reservoirs. Some reservoirs with enough natural pressure the oil and gas flows to the surface without secondary lift techniques. Often, however, other methods are required to bring them to the surface. These include a variety of pumping, injection, and lifting techniques used at various locations, such as at the surface wellhead (e.g. use of rocking beam suction pumping), at the bottom down-hole of the well (e.g. use of submersed pumping), with gas injection into the well casing creating lift and other techniques. Each of these techniques results in crude petroleum oil and gas emerging from the well head as a multiphase fluid with varying proportions of oil, water, and gas. For example, a gas lift well has large volumes of gas associated with the well. The gas-to-oil volumetric ratios can be 200 standard cubic feet of gas per barrel of oil, or higher. The complexity of the flow regimes can create large measurement uncertainties depending upon the methods.
Multiphase measurement typically provides an oil company and a stakeholder the amount of gas, oil, and water and the average temperature, pressure, gas/oil ratio, and gas volume fraction that a well produces in a day. Conventional three-phase separators, two-phase separators, and modern multiphase flow-through measurement devices capture this information. Conventional three-phase systems separate the gas, oil, and water streams, then measure the three streams with a flow meter. A two-phase system separates the gas from the liquids (oil, water), measures the flow of each, and uses a water/oil detector to obtain the oil and water rates. Newer multiphase systems use multiple detection methods, such as Venturi, gamma, or cesium sources, as well as other methods to obtain the oil, water, and gas flow rates without separation.
These tests are used to determine each well's contribution to the output streams of the production plant. The total measured production at the output is typically at lower pressures and temperatures than the inputs measured at the well test systems, which complicates the comparison of the sums of the individual well streams. The sum of the individual well test results compared to the total seen at production may be expressed as a ratio and is called the “allocation factor”. Typically, the allocation factor value may range from 0.9 to 1.1.
Since crude oil shrinks with temperature, the shrinkage must be compensated for in making the comparison. Gas volume is dependent upon temperature and pressure and this must also be considered. The test separator measurement under normal operating conditions cannot be expected to give an uncertainty of better than +/−10% to +/−20% of the reading of each phase volume flow rate. The metering uncertainty of conventional single-phase meters on a test separator varies from field to field and in most cases is very difficult to estimate.
Hydrocarbon well optimization methods include adjusting the well operating parameters and employing reservoir stimulation techniques. The effectiveness of such optimization methods is greatly enhanced if accurate well test data of the oil well is available. Specifically, in one context of hydrocarbon well production optimization, it is important to be able to determine the amount of water mixed with the crude oil. The water may be present as naturally produced ground water, water from steam injection, and/or well injection water that eventually mixed with the oil as a result of a reservoir stimulation process. One such stimulation process is known as Steam Assisted Gravity Drain stimulation (“SAGD”). Another stimulation process is the “huff and puff” stimulation method where steam is intermittently injected into the reservoir. Different types of stimulation processes can have different phase states upon start-up of the well.
A further complexity to the multiphase characteristics of crude petroleum oil stems from the fact that a given well with a given production technique does not produce a constant multiphase composition and flow rate. Production depletes reservoirs, thereby decreasing the output of hydrocarbon over time. On the other hand, well composition and volumetric output can change in a matter of seconds because a well is a vertical separator that tends to separate the gas and the liquids. For example, upon start-up, a well can take several minutes or several hours to reach steady-state operation. Therefore, a well stabilization period, typically called a “purge time”, is done before starting the actual well test.
Regardless of production technique, one constant requirement for all hydrocarbon well operations is the need to determine how much oil and gas a given well is producing over a given period (i.e., the well production rate). To that end, well testing is routinely conducted on a given well to establish the gas, water and oil flow rates.
The need for accurately characterizing a particular well's performance is important to well operation and production output optimization. Optimization operations reduce equipment failure and improve decisions to work over a well. Variable multiphase flow patterns are generated by drill string behavior, various bottom hole configurations, and possible differing layers of oil and gas in a given hydrocarbon formation. Interpreting the well characterization data requires consideration of differing patterns of well behavior, various cyclic well behaviors, and varying durations of peak and minimum flows.
The variable production techniques and the resulting varying multiphase fluids present significant challenges to well testing systems and methods. For the most part, determination of the volume of gas and volume of liquid produced over a given time is relatively easily established using gas-liquid separation techniques, and gas and liquid flow metering techniques known to a person having ordinary skill in the art of quantifying hydrocarbon well output production. However, a significant challenge lies in determining if the well test is acceptable and without reliability problems.
Data Collection During Well Testing
The actual proposed use of the well test data is not always specified in the beginning Whether for field evaluation, development and allocation of production of a new field, process control, and/or payment of taxes, the manner in which the data was obtained is important to the validity of using the data for the stated purpose. Field evaluation may only require a +/−10% accuracy, while fiscal measurement may place much tighter requirements on the design. If the data is obtained by integration over 10 minute intervals, the problems in separator efficiency, slug handling, and level control may not be observable in the data. Conversely, if the data is obtained and displayed on a 5 second interval, most operators would not interpret the data in a favorable light.
The perceived operation of a system versus the actual operation is very different in some cases. The rapid changing of data due to fluid characteristics may be interpreted as a problem with the system. Thus, if the same data had been integrated and presented differently, the same operator would believe the system is okay. Although unacceptable to the operator, this “fast” data may be of much interest to the production engineer or the reservoir engineer, since it may shed light on the actual performance of the well, the separator, and the control system. Data for fiscal use may only be the sum total oil/water/gas production per day with all periods of less than one day being inconsequential.
Various industry groups may specify sizes and types of particular components to be used in well test systems. The vessel itself may be purchased from a separator design company with the remainder specified by an engineering company. In too many instances, the designer is removed from the person specifying the field parameters and needs. In many instances, the company designing the equipment may never actually visit the field or talk to the end users of the equipment. This makes the process very dependent on the communications between the various operating groups and leads to many problems once the equipment is on site. Once the equipment arrives on the site and is commissioned by a third party, the operation is turned over to the field production groups. Thus, in many cases, it is the end user that must make the system work.
Different segments of the market require different solutions depending on whether the customer is in the Arctic, South America, or the North Sea. The difference may not necessarily be in the technology, but in the application of technology in the field. Heavy oil versus light oil applications require very different approaches to well tests. Another difference could be in the method of presenting the data to the end user. The equipment may need to be designed for simplicity or complexity depending upon the measurement needs, capital money available, and knowledge and sophistication of the operators of the fields. Several other design parameters that may affect well testing include: fluid viscosity, water cut, gas-oil ratio, oil density, water salinity, gas composition, distance of test equipment from the well head, flow stability, and reporting requirements of the operation. Today, fewer technicians are available and higher equipment reliability is required. The system maintenance must be straightforward and simple to identify problems.
Although the selection of the measurement instruments is very important to the end accuracy, the instruments are but one part of the system. The system must work as a whole and the data obtained must be consistent with the end use. The algorithms used to interpret the data collected from the separate instruments are critical to the operation of the whole. This is true whether it is a complex state-of-the-art multiphase analyzer or a two-phase vessel with standard instrumentation.
Thus, there is a need for improved systems and methods for evaluating the quality of data being measured in a well test. More particularly, there is a need for improved systems and methods for summarizing and qualifying the data measured in a well test in order to accept or reject a given well test.